Method and apparatus for shaping a well hole

ABSTRACT

A method of shaping a wellbore comprising attaching a drilling apparatus to a drill string, which has a side cutting sub-assembly with both cutting and gauging surfaces; a fluid circulating sub-assembly which has nozzles directing fluid up the wellbore and past the cutting surfaces; and a bullnose assembly with forward pointing nozzles and a bullnosed front end to prevent catching in ledges of a rough drilled wellbore. The drilling apparatus is then passed through the wellbore such that the side cutting sub shears arch wellbore walls of dog legs to ease the turns and smooth the bore wall in preparation for running liner/casing or other down hole assemblies which previously may have had difficulty going in hole.

BACKGROUND OF THE INVENTION CROSS-REFERENCE TO RELATED APPLICATIONS

Not Applicable.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT

Not Applicable.

BACKGROUND OF THE INVENTION

Directional drilling is the practice of drilling non-vertical wells. This was originally an accidental occurrence caused by rock formations or imprecise operations which caused the drilling head to diverge from the intended vertical course. The value of drilling in a direction other than straight down was realized as beneficial to the industry.

Several methods for drilling were developed which created inclinations, deviations from the vertical, of the wellbore. Down hole drilling motors, also known as mud motors, driven by the hydraulic power of drilling mud circulated down the drill string allow the drill string to remain stationary while only the bit rotates. By introducing a bent pipe (a “bent housing”) between the mud motor and the drill string, the direction of the wellbore can be selected and controlled. There are also steerable motors which incorporate devices for changing the inclination on the fly. Other techniques and equipment also exist for directional drilling control.

Three components are measured to determine the position of a wellbore: the depth of the point (measured depth), the inclination at the point, and the magnetic azimuth at the point. These three components are collectively called a survey. Developments in measuring the three components allow wells to be directed to precise locations and orientations.

A series of consecutive surveys are used to track the progress and location of a wellbore as it progresses along a desired path. For various reasons periodic surveys are only taken at intervals of 30-500 feet, with 90 feet (the length of a typical “stand”) being common during active changes in angle or direction. These periodic surveys result in a series course corrections, and thus a wellbore is a collection of dog leg turns rather than a smooth curving arc. Since drilling often is stopped to produce a more accurate survey, increasing the number of surveys slows the drilling progress. Therefore, the tendency in rig operation is to minimize the frequency of surveys resulting in the need for coarser course corrections.

Aggressive bits used in progressive drilling results in a rough bore wall. Rough bore walls combined with the dog leg turns described above create a difficult environment for inserting and removing download drilling equipment (“Bottom Hole Assemblies” or “BHA”). The rough geometry of the bore walls also makes it difficult for casing/liners to be inserted into a borehole. A dog leg that is too sharp may exceed the bending radius of the liner. Rough walls and dog legs can catch and snag the liner's leading edge preventing it from reaching the end of the lateral. Increased friction along the sides of the casing may call for more force to be necessary to push the casing into place. This increased force can cause the casing to flex, expand, buckle, or keyhole.

Use of aggressive bits to widen a bore hole or ease the curves can cause a divergence in the well path. Sidetracks or ledges can be created further resulting in an unshapely hole. Further, aggressive bits can over enlarge a wellbore resulting in added expenses, as extra material is necessary to cement the casing in the wider bore hole. Constantly stopping to measure or check bore hole conditions is time consuming and costly.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1 illustrates dog leg curves which obstruct inserting drill strings down a rough wellbore.

FIG. 2 illustrates a front view of a drilling apparatus in accordance with an exemplary embodiment of the invention.

FIG. 3 shows an exploded cut away view of the three possible sub-assemblies of a drilling apparatus in accordance with an exemplary embodiment of the invention.

FIG. 4 illustrates the use of a fluid circulating sub-assembly to clear cuttings from a side cutting sub-assembly and bullnose in accordance with an exemplary embodiment of the invention.

FIG. 5A-5C shows the progression of a drilling apparatus through a dog leg curve to reshape a wellbore in accordance with an exemplary embodiment of the invention.

DETAILED DESCRIPTION OF THE PREFERRED EMBODIMENTS

Disclosed herein is a design for an apparatus referred to in general terms as a bottom hole assembly (BHA). The apparatus is used during well drilling operations to shape and clean a wellbore after the initial pass by an aggressive drill head. In particular, the apparatus' primary function is to clean the curves and lateral portions of a horizontal well. The preferred embodiment of the apparatus is a series of sub-assemblies which are connected through pin threads and box threads which secure the sub-assemblies end to end along a common central axis in to a single apparatus. The apparatus is then secured to the bottom end of a drill string and ran down an existing rough cut bore hole.

The sub-assemblies of particular interest to this disclosure are a side cutting sub-assembly, a fluid circulating sub-assembly, and a bullnose sub-assembly. One skilled in the art would appreciate that the features of the individual sub-assemblies could be incorporated into fewer sub-assemblies, or into a complete single assembly without means for separating into sub-assemblies. Further, one skilled in the art would appreciate that additional features may be incorporated in the BHA without compromising the functionality of the assembly as described herein. For simplicity and clarity in this disclosure, each sub-assembly is described as a separable unit. Further, the relative placement of each sub-assembly with respect to the others is described below when doing so makes their function and relative interactions relevant. Nothing in this disclosure is meant, or should be interpreted as limiting the placement of the sub-assemblies, or requiring the strict use of each assembly as a separate assembly, or the incorporation of other functionality or features not described herein.

The apparatus is fitted to the end of a drill string by use of a pin or box thread connector at the top of the BHA and is used to clean rough bore walls created by aggressive cutting heads during initial and subsequent well borings. Proper use of the device will ease the abrupt angle changes of dog legged turns as well as finish rough bore walls and remove ledges, thus producing smooth flowing curves and clean bores which are more conducive to insertion of liner/casing and the insertion and removal of other BHAs.

The side cutting sub-assembly is a tubular drill structure which utilizes rows of cutting surfaces oriented longitudinally on the outer surface. The cutting surfaces in the preferred embodiment are Polycrystalline Diamond Compact (PDC) cutters. The plurality of these rows are interspersed around the circumference along with longitudinally oriented flow channels which allow mud to flow past the rows of cutting surfaces thus removing the cuttings produced by drilling operations and carrying them back up the wellbore past the drill string to the surface.

One skilled in the art would appreciate that the cutting surfaces could be of other materials. One skilled in the art would appreciate that the actual cutting surfaces or structures, the quantity, orientation and rotational speed of such cutting surfaces can be tailored for the environment in which the tool is to be used. Further, a variety of cutting surfaces or structures may be intermixed for specific environments.

To prevent the cutting surfaces from aggressively re-shaping the wellbore by causing ledges, pockets, or tangents, the cutting surfaces are alternately interspersed with gauging surfaces. Gauging surfaces are hard surfaces which do not substantially wear or cut when in contact with the bore wall. Gauging surfaces prevent the cutting surfaces from penetrating too deeply into the bore walls. In the preferred embodiment, the gauging surfaces are diamond domes (DD) which are hemispheres of approximately the same height as the PDC cutting surfaces. They are oriented around the cutting surfaces such that the gauging surfaces contact the bore wall and prevent cutting surfaces from penetrating too deeply into the bore wall while still allowing the cutting surfaces to contact and remove any formation which intrudes into the wellbore.

To improve the efficiency of the assembly, fluid flow is used to remove cuttings and to lubricate and cool the BHA. As is traditional in BHA's fluid is circulated down the drill string's hollow center. This fluid reaches the bottom of the drill string and exits the center through voids in the BHA to then return to the surface along the outside of the drill string. The fluid circulating sub-assembly disclosed here uses a plurality of nozzles to further pressurize drilling fluids. These pressurized drilling fluids are then directed back up the wellbore past the cutting surfaces of the side cutting sub-assembly to remove the built up cuttings which slow drilling processes.

The bullnose assembly has a rounded edge at the lower end so it will not catch on ledges or rough outcropping of the wellbore as it progresses down the well. While the majority of the bullnose has a hollow core, the bottom of the bullnose assembly is closed off with optional nozzles pointing in front or down the bore hole. The nozzles help clear the wellbore before the drilling apparatus by washing the cuttings to the side and back up the wellbore.

In operating the drilling apparatus, the nozzles can be adjusted to configure the Total Flow Area (TFA) out the bottom of the bullnose sub-assembly, or out the fluid circulating sub-assembly to adjust the clearing of cuttings. There are several factors which afford the choice of nozzle configurations including mud weight, hole depth, drill pipe used, maximum standpipe pressure, desired gallons per minute (gpm) to clean hole, etc. The nozzle configuration can also be adjusted to provide uneven flow in order to create turbulent flow and thus evacuate existing and new cuttings out of the hole. The bullnose nozzles can be configured to ensure the capability to wash through bridges and reduced hole sizes. The fluid circulating sub can be configured to maximize circulation cuttings up and out of the hole.

When the apparatus or BHA is being lowered down the vertical of a wellbore the side cutting sub-assembly may contact the bore wall with enough force to perform significant cutting actions in areas where the structures penetrate causing a restricted hole size, or irregular shapes of the wellbore. Whenever, when the BHA reaches a dog leg turn, the bullnose will contact the outside of the turn and the weight of the drill string will cause the side cutter assembly to contact the inside of the dog leg with enough force to cut and round the angled corner. When the BHA is lowered past the dog leg turn and into the straight part of the curve, the flex of the drill string will force the side cutter assembly against the outer wall with a force that will allow it to cut into the outside wall, thus widening the curve.

As the BHA is cutting the wellbore, the gauging surfaces rub against the bore wall and prevent the cutting surfaces from cutting too deeply. The bullnose's curved edges keep the BHA from catching on a ledge or from going off course to diverge from the original wellbore.

Turning now to the drawings, FIG. 1 illustrates dog leg curves which obstruct inserting drill strings down a rough wellbore. The drilling rig (100) pushes a casing or liner (110) down a wellbore (150). In traditional drilling, intermitting course correction cause curves (153) in the wellbore (150) to actually be a series of dog leg turns (155) which gradually redirect the wellbore to a lateral (157). However aggressive drilling and formation properties may leave a rough wellbore (illustrated in the enlarged section) where the bottom of the casing or liner (120) can get caught on edges of the wellbore (150).

FIG. 2 illustrates a front view of a drilling apparatus in accordance with an exemplary embodiment of the invention. The drilling apparatus (200) is an assembly of three sub-assemblies (220, 250, and 270). The sub-assembly illustrated on top of the stack is a side cutting sub-assembly (220), which has a pin thread (201) at the top end and a box thread (202, not visible) at the lower end. The tubular body (221, not designated) contains a plurality of cutter arrays (222) interspersed with flow channels (223) around the circumference of the tubular body (221). A cutter array (222) has alternating cutting surfaces (226) and gauging surfaces (225). Cutting channels run between the surfaces (225, 226) from one flow channel (223) to another.

One skilled in the art would appreciate that the pin thread and box thread described above could be replace with other joining apparatus for linking the sub assembly to other sub assemblies or for linking the sub assembly to the components of the drill string. Further, one skilled in the art would appreciate that the pin threads and box threads could be eliminated such that one or more sub assemblies are joined into a single new assembly comprising all aspects of the described sub assemblies.

The sub-assembly illustrated in the middle of the stack is a fluid circulating sub-assembly (250). A plurality of up pointing or backward facing nozzles (255) direct fluid back up the annulus past the cutter arrays (222). The fluid circulating sub-assembly (250) has a pin thread at the top end which is illustrated as a thread joint (203) where it mates with the box thread located at the bottom of the side cutting sub-assembly (220).

The sub-assembly illustrated on the bottom of the stack is a bullnose sub-assembly (270). The closed bottom (288) of the bullnose sub-assembly (270) is rounded on the edges (285). The bullnose sub-assembly (270) has a pin thread at the top end which is illustrated as a thread joint (203) where it mates with the box thread located at the bottom of the fluid circulating sub-assembly (250).

FIG. 3 shows an exploded cut away view of the three possible sub-assemblies of a drilling apparatus in accordance with an exemplary embodiment of the invention. The drilling apparatus (200) is an assembly of three sub-assemblies (220, 250, and 270). It is made up of a hollow tubular body (221) which has a central channel (210) The first sub-assembly, illustrated on top of the stack, is a side cutting sub-assembly (220), which has a pin thread (201) at the top end and a box thread (202) at the lower end. The tubular body (221) contains a plurality of cutter arrays (222) interspersed with flow channels (223, not illustrated) around the circumference of the tubular body (221). A cutter array (222) has alternating cutting surfaces (226) and gauging surfaces (225). Cutting channels run between the surfaces (225, 226) from one flow channel (223) to another.

The second sub-assembly, illustrated in the middle of the stack, is a fluid circulating sub-assembly (250). A plurality of up-pointing or backward-facing nozzles (255) direct fluid from the central channel (210), back up the annulus past the cutter arrays (222). The fluid circulating sub-assembly (250) has a pin thread at the top end (201) and a box thread (202) at the lower end.

The third sub-assembly, illustrated on the bottom of the stack, is a bullnose sub-assembly (270). The closed bottom (288) of the bullnose sub-assembly (270) is rounded on the edges (285) to create the bullnose (280) at the lower end of the assembly. The upper end of the assembly has a pin thread (201). The bullnose assembly (270) has nozzles (275) in the bottom (288) of the assembly which direct fluid from the central channel (210) out into the wellbore.

FIG. 4 illustrates the use of a fluid circulating sub-assembly to clear cuttings from a side cutting sub-assembly in accordance with an exemplary embodiment of the invention. In this view, the drill string (110) is shown pushing the drilling apparatus (200, not designated) down through the wellbore (150). The up nozzles (255) in the fluid circulating sub-assembly (250) direct fluid (410) up the wellbore to remove cuttings (450) from the wellbore (150). Further, down facing nozzles (275) located in the bullnose (280) direct fluid (420) ahead of the BHA to loosen and remove cuttings (450) from the wellbore (150).

FIG. 5A-5C shows the progression of a drilling apparatus through a dog leg curve to reshape a wellbore in accordance with an exemplary embodiment of the invention. FIG. 5A show what happens as the drill string (110) pushes the drilling apparatus (200, not designated) down through a curve (153) in the wellbore (150) the bullnose (270) comes in contact with the side of the curve (153).

FIG. 5B show that as the drill string (110) continues to push the drilling apparatus (200) through the dog leg turn (155) of a curve (153) in the wellbore (150), the side cutting sub-assembly (220) is forced against the inside of the dog leg turn (155) allowing the side cutting sub-assembly (220) to cut into the bore wall easing the curve (155′ in FIG. 5C)

FIG. 5C shows that as the drill string (110) continues past the eased dog leg turn (155′) the drill string (110) will continue to flex (exaggerated for clarity) to force the side cutting assembly (220) against the outside wall of the curve (153). The bullnose (270) will continue to steer the drilling apparatus (200) through the existing wellbore (150) preventing divergent paths from being cut.

The diagrams in accordance with exemplary embodiments of the present invention are provided as examples and should not be construed to limit other embodiments within the scope of the invention. For instance, heights, widths, and thicknesses may not be to scale and should not be construed to limit the invention to the particular proportions illustrated. Additionally some elements illustrated in the singularity may actually be implemented in a plurality. Further, some element illustrated in the plurality could actually vary in count. Further, some elements illustrated in one form could actually vary in detail. Further yet, specific numerical data values (such as specific quantities, numbers, categories, etc.) or other specific information should be interpreted as illustrative for discussing exemplary embodiments. Such specific information is not provided to limit the invention.

The above discussion is meant to be illustrative of the principles and various embodiments of the present invention. Numerous variations and modifications will become apparent to those skilled in the art once the above disclosure is fully appreciated. It is intended that the following claims be interpreted to embrace all such variations and modifications. 

What is claimed is:
 1. An apparatus for shaping of a wellbore comprising: a tubular shaped main body (221); and a side cutting assembly (220) having a plurality of cutting surfaces (226) arranged around the body's (220) outer circumference.
 2. An apparatus for shaping of a wellbore as described in claim 1 wherein the side cutting assembly (220) further comprises a plurality of gauging surfaces (225) arranged around the body's (220) outer circumference.
 3. An apparatus for shaping of a wellbore as described in claim 2 wherein the cutting surfaces (226) and gauging surfaces (225) are alternately grouped (222) in alignments running longitudinally.
 4. An apparatus for shaping of a wellbore as described in claim 3 wherein flow paths (223) are longitudinally arranged between the alignments (222) of cutting (226) and gauging surfaces (225).
 5. An apparatus for shaping of a wellbore as described in claim 4 wherein cutting channels (227) pass between the cutting (226) and gauging surfaces (225) running from one flow path (223) to another.
 6. An apparatus for shaping of a wellbore as described in claim 1 wherein the cutting surfaces (226) are Polycrystalline Diamond Compact (PDC).
 7. An apparatus for shaping of a wellbore as described in claim 2 wherein the gauging surfaces (225) are Diamond Domes (DD).
 8. An apparatus for shaping of a wellbore, as described in claim 1 further comprising: a closed lower end (288); wherein the closed lower end (288) has substantially rounded edges (285) forming a bullnosed shape (280).
 9. An apparatus for shaping of a wellbore, as described in claim 8 further comprising: a plurality of nozzles (255) passing through the walls of the tubular shaped body (221) for directing fluid like substances from the center cavity (210) to the outside of a tubular shaped main body (221).
 10. An apparatus for shaping of a wellbore, as described in claim 9 wherein the nozzles (255) are configurable to adjust the Total Flow Area (TFA).
 11. An apparatus for shaping of a wellbore, as described in claim 10 wherein a plurality of the nozzles (255) are below the side cutting assembly (220); and said plurality of nozzles (255) are angled to direct flow up past the side cutting assembly (220).
 12. An apparatus for shaping of a wellbore, as described in claim 11 wherein the plurality of nozzles (255) are angled to direct flow up are in a separatable sub-assembly.
 13. An apparatus for shaping of a wellbore, as described in claim 10 wherein a plurality of the nozzles (275) are located near or within the bullnose (280) end of the main body (200) and oriented to direct flow ahead of the apparatus (200) down the wellbore (150).
 14. An apparatus for shaping of a wellbore, as described in claim 13 wherein the nozzles (275) are configurable to adjust the Total Flow Area (TFA).
 15. A method of shaping a wellbore comprising: preparing an wellbore for operations; attaching a drilling apparatus (200) to a drill string (110); said drilling apparatus (200) comprising: a side cutting sub-assembly (220) having a plurality of cutting surfaces (226): flow paths (223) longitudinally between the cutting surfaces (226); and cutting channels (227) between the cutting surfaces (226) running between flow paths (223); a bullnose sub-assembly (270).
 16. A method of shaping a wellbore, as described in claim 15, further comprising: passing the drilling apparatus (200) into an irregularly shaped section (155) of a wellbore (150) such that the bullnose (280) forces the side cutter (220) into the side of the irregularly shaped section (155) causing the side cutting structures (226 & 225) to remove material (450) from the wall of the section (155).
 17. A method of shaping a wellbore, as described in claim 15, further comprising: passing the drilling apparatus (200) through an irregularly shaped section (155) of a wellbore (150) such that the drill string (110) forces the side cutter (220) into the side of the irregularly shaped section (155) causing the side cutting structures (225 & 226) to remove material (450) from the wall of the section (155).
 18. The method of shaping the wellbore as described in claim 15 further comprising: attaching a drilling apparatus (200) to a drill string (110) which further comprises: a plurality of gauging surfaces (225), using gauging surfaces (225) to avoid aggressive cutting of the wellbore walls.
 19. The method of shaping the wellbore as described in claim 15 further comprising: attaching a drilling apparatus (200) to a drill string (110) which further comprises: an up flow nozzle sub-assembly (250); and directing up flow nozzle's (255) total flow area to clear cuttings (450) from the side cutting assembly (220) during cutting operations.
 20. The method of shaping the wellbore as described in claim 15 wherein preparing the wellbore for operations further comprises: inserting a circulating drilling apparatus (250) into the wellbore; rotating the circulating drilling apparatus (250) into the wellbore; running fluid through the circulating drilling apparatus (250) in the wellbore; and washing existing cuttings (450) from the well bore (150). 